Wellbores may be drilled in a number of different configurations. Conventionally, wellbores have been drilled in a vertical orientation. However, during drilling, the drill bit may deflect or deviate from vertical for many reasons including the orientation of the formation which the drill bit encounters, the weight on the drill bit, and the penetration rate of the drill bit. Other wellbores have been intentionally drilled in a slant configuration with a constant slant angle to the surface or in a manner such that the wellbore intentionally deviates or changes direction, typically from a vertical to a horizontal orientation. As a result, most wellbores will contain intentional or non-intentional deviations or direction changes within the wellbore.
Once drilled and cased, a tubing string is run into the wellbore, and a reciprocating rod or a rotating rod is run through the tubing string for production of the well. The qualities of the produced fluids and solids pumped from the wellbore, including viscosity, weight and abrasivity, may vary depending upon the amount of water, in a free or emulsified state, and the amount of sand and other fine solids from the formation that are produced along with the produced hydrocarbons. Lighter less viscous hydrocarbon production often precipitates out paraffin or wax, which collects on the outer surface of the rod and the inner surface of the tubing string.
During production, the configuration of the wellbore and the qualities of the produced fluids, being water and produced hydrocarbons, and solids can impact greatly on the wear of the outer surface of the rod or rod couplings, the inner surface of the tubing string and the inner surface of the downhole pump barrel. It has been found that the amount of wear typically increases with an increase in the slant angle of the wellbore or an increase in the severity of the dogleg which is the rate at which the direction or angle of the wellbore changes. The amount of wear also typically increases with an increase in the amount of water or sand produced along with the hydrocarbons. Further, wax or paraffin collection may gradually restrict the flow of the produced fluids and solids in the tubing string and increase the downhole pump pressure.
The problems of wear and restricted fluid flow are potentially very costly as they may result in equipment failures and lost production time. For instance, the rod or rod couplings may wear to the point of separation or the action of the rod may wear a hole in the tubing string. This may result in the leakage of produced fluids and solids back down the wellbore. As a result, various attempts have been made to protect the rod from wear such as hard surfacing the rod couplings, coating them with teflon and other materials, or providing roller guides or centralizers for the rod within the tubing string. However, these approaches provide limited protection against wear on the tubing string or the pump barrel and the buildup of paraffin or wax.
Wear on the tubing string and the pump barrel arid the reduction of any paraffin or wax buildup has been addressed by tubing rotators. Tubing rotators rotate the tubing string within the wellbore, which distributes the wear over the entire internal surface of the tubing string, and thus prolongs its life. As welt, the constant movement of the inner surface of the tubing string relative to the rod inhibits or reduces the buildup of paraffin or wax.
In conventional wells, at least a portion of the wellbore is typically completed by cementing a casing string into the wellbore. After the casing string is installed, a casing bowl is typically welded or screwed to the top of the casing string at the surface. To suspend the tubing string in the wellbore, when a tubing rotator is not in use, a dognut conforming to the inner surface of the casing bowl is typically hung within the casing bowl. The other parts of the wellhead are then mounted to the top of the casing bowl. In order to service the well, the rod and the tubing string must be removed. However, any movement or disturbance of the tubing string during servicing may lead to a blowout. To avoid this risk in a conventional well without a tubing rotator, the portion of the wellhead above the casing bowl is removed and a blowout preventer is mounted to the casing bowl. The dognut with the attached tubing string is then removed through the blowout preventer.
Known tubing rotators, such as those described in U.S. Pat. No. 2,599,039 issued Jun. 3, 1952 to Baker, U.S. Pat. No. 2,471,198 issued May 24, 1949 to Cormany, U.S. Pat. No. 2,595,434 issued May 6, 1952 to Williams, U.S. Pat. No. 2,630,181 issued Mar. 3, 1953 to Solum and U.S. Pat. No. 5,139,090 issued Aug. 18, 1992 to Land, suspend the tubing string from, and are mounted to, the upper portion or flange of the casing bowl in a manner that a blowout preventer cannot be installed or mounted to the casing bowl without first removing the portion of the tubing rotator supported by the casing bowl. Removal of the necessary portion of the tubing rotator requires movement or disturbance of the tubing string. This may lead to a blowout. In effect, known tubing rotators are typically supported from the same area or surface of the casing bowl required for mounting of the blowout preventer. Thus, the tubing rotator interferes with the installation of the blowout preventer and the blowout preventer cannot be installed during servicing without first moving the tubing string.
Further, known tubing rotators, such as that shown in Williams, may include a dognut or dognut-shaped part, compatible with the inner surface of the casing bowl, for suspending the tubing string within the casing bowl. This design requires the lower portion of the tubing rotator to conform to the shape of the inner surface of the casing bowl, which may be limiting given that casing bowls often vary in shape and size from wellhead to wellhead. The result is that a specific tubing rotator may not necessarily be usable with every wellhead as the size and shape of the lower portion of the tubing rotator may not be compatible with every casing bowl to which it is to be mounted.
Further, the structure of many known tubing rotators, such as Cormany and Williams, requires the use of an exposed swivel connection in the wellhead above the tubing rotator which may weaken the overall structure of the wellhead and add significant height to it.
As well, in order to provide even distribution of the wear on the rod and the tubing string, the tubing string is preferably turned automatically on a continuous basis. Means for operating the tubing rotators to provide for automatic rotation of the tubing string are known. For example, Solum describes an apparatus for continuously rotating the tubing string which is operated by hydraulic pressure. However, the means for operating the tubing rotator are preferably driven by, and combined with, the producing action of the wellhead, as shown in Cormany, Williams, Land and U.S. Pat. No. 2,693,238 issued Nov. 2, 1954 to Baker. These patents all provide for a tubing rotator which is connected to a wellhead having a reciprocating rod attached to a walking beam. The tubing rotator is continuously driven by the reciprocating action or movement of the walking beam. However, these operating means are not always useful given that many wellheads today use a rotating rod for production of the well rather than a reciprocating rod and walking beam structure.
Finally, damage may result to the joints or connections of the tubing string, the tubing rotator and the means for operating the tubing rotator if too much torque is generated by the operating means and the tubing rotator, for example, when the tubing string becomes stuck in the wellbore. Thus, it is preferable that a torque limiting device be incorporated in series with the operating means and the tubing rotator. In Williams, frictional contact between an inner mandrel and the rotating means provides for some limiting of the generated torque. However, the torque at which slippage occurs is not adjustable.
Therefore, there is a need in the industry for a relatively compact apparatus, for attachment to a wellhead, for both suspending and rotating a tubing string contained within a wellbore that can be partially dismantled during servicing for removal from the wellhead in a manner to allow for the mounting of a blowout preventer on the wellhead without first moving the tubing string within the wellbore so that once the blowout preventer is mounted on the wellhead, the remaining parts of the tubing rotator and the tubing string may be removed through the blowout preventer. Further, there is a need for the apparatus, and similar rotating mechanisms, to include means for operatively connecting to a rotating rod such that the rotation of the rotating rod operates or engages the apparatus. Finally, there is a need for adjustable means for limiting the torque applied to the apparatus and the means for connecting to the rotating rod.